As low sulfur natural gas fields are being depleted, gas production from sour gas fields has become increasingly common to meet today's energy demands. Acid gas removal from these sour gas fields, and especially removal of highly sour gas fields, requires significant capital investments and operating costs. While these plants must demonstrate their economics, they must also comply with today's gas pipeline specifications with increasing stringent requirements on energy efficiency and emissions standards. Compounding these challenges is that the acid gas content of these gas fields often increases over time, which often renders conventional acid gas removal plants ineffective to produce a product that complies with current consumer gas pipeline specifications.
Acid gases can be removed using a conventional amine process, however, such process is typically not economical as the amine solvent circulation must be increased proportionally with the feed gas acid gas content, requiring higher steam heating duty in solvent regeneration, and hence higher greenhouse gas emissions. Moreover, there is also an upper limit in the acid gas loading capacity (i.e., mol of acid gas per mole of amine) which is predominantly controlled by the chemical equilibrium between amine and the acid gases. To overcome at least some of these problems, physical solvents may be employed that operate on the principal of Henry's law in which acid gas loading of the solvent increases with the acid gas content and partial pressure. Thus, and at least conceptually, physical solvent absorption of acid gas is relatively attractive for high acid gas fields. Solvent regeneration can be accomplished, to at least some extent, by flash regeneration that eliminates the need for heating and so reduces greenhouse gas emissions. However, without external heating, physical solvent can only be partially regenerated and is therefore often unsuitable for treatment of sour gases to produce a product that meets pipeline gas specifications (e.g., 1 mol % CO2, 4 ppmv H2S). For example, when conventional physical solvent processes are used for treatment of a feed gas with high H2S content (e.g., ≧100 ppmv), they typically exceed H2S limits for the treated gas. To improve the gas quality, a sulfur scavenger bed can be used to adsorb H2S in the feed gas or product. However, such solution is temporary, and in most cases requires the presence of a sulfur plant. Moreover, disposal and handling of the spent sulfur contaminated beds is often environmentally unacceptable.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other things, H2S levels in the treated gases are often high, and the use of physical solvent, without heat application, would not be suitable to produce treated gas that meets gas pipeline specifications. Therefore, there is still a need to provide improved methods and configurations for acid gas removal.